UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

[X]

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarter ended March 31, 2010

[  ]

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ___ to ___

QUESTAR CORPORATION

(Exact name of registrant as specified in its charter)

STATE OF UTAH	001-08796	87-0407509
(State or other jurisdiction of incorporation or organization)	Commission File No.	(I.R.S. Employer Identification No.)

180 East 100 South Street, P.O. Box 45433 Salt Lake City, Utah 84145-0433

(Address of principal executive offices)

Registrant's telephone number, including area code (801) 324-5699

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [   ]

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes [X]   No [   ]

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.  (Check one):

Large accelerated filer [X]	Accelerated filer [   ]
Non-accelerated filer [   ]   (Do not check if a smaller reporting company)	Smaller reporting company [   ]

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes [   ]   No [X]

At April 30, 2010, there were 175,093,545 shares of the registrant's common stock, without par value, outstanding.

Questar Corporation

Form 10-Q for the Quarter Ended March 31, 2010

TABLE OF CONTENTS

Page

PART I.

FINANCIAL INFORMATION

ITEM 1.

FINANCIAL STATEMENTS (Unaudited)

3

Consolidated Statements of Income for the three months ended

  March 31, 2010 and 2009

3

Condensed Consolidated Balance Sheets as of March 31, 2010

  and December 31, 2009

4

Condensed Consolidated Statements of Cash Flows for the three months ended

  March 31, 2010 and 2009

5

Notes Accompanying the Condensed Consolidated Financial Statements

6

ITEM 2.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND

  RESULTS OF OPERATIONS

16

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

25

ITEM 4.

CONTROLS AND PROCEDURES

26

PART II.

OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

27

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

27

ITEM 6.

EXHIBITS

28

SIGNATURES

28

Questar 2010 Form 10-Q

2

PART I. FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS.

QUESTAR CORPORATION

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	3 Months Ended March 31,
	2010	2009
	(in millions, except per share amounts)
REVENUES
Market Resources	$576.3	$476.1
Questar Pipeline	47.0	40.7
Questar Gas	360.7	405.7
Total Revenues	984.0	922.5
OPERATING EXPENSES
Cost of natural gas and other products sold     (excluding operating expenses shown separately)	325.8	315.3
Operating and maintenance	103.5	100.3
General and administrative	51.2	41.2
Production and other taxes	37.5	29.0
Depreciation, depletion and amortization	186.3	161.3
Exploration	3.6	3.1
Abandonment and impairment	7.6	3.7
Total Operating Expenses	715.5	653.9
Net gain (loss) from asset sales	(0.8)	1.9
OPERATING INCOME	267.7	270.5
Interest and other income	3.5	4.4
Income from unconsolidated affiliates	1.8	1.6
Unrealized and realized (loss) on basis-only swaps		(138.3)
Interest expense	(34.1)	(31.8)
INCOME BEFORE INCOME TAXES	238.9	106.4
Income taxes	(88.0)	(38.7)
NET INCOME	150.9	67.7
Net income attributable to noncontrolling interest	(0.6)	(0.5)
NET INCOME ATTRIBUTABLE TO QUESTAR	$150.3	$  67.2
Earnings Per Common Share Attributable To Questar
Basic	$0.86	$0.39
Diluted	0.85	0.38
Weighted-average common shares outstanding
Used in basic calculation	174.9	173.8
Used in diluted calculation	177.2	175.9
Dividends per common share	$0.13	$0.125

See notes accompanying the condensed consolidated financial statements

Questar 2010 Form 10-Q

3

QUESTAR CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

	March 31, 2010 (Unaudited)	December 31, 2009
	(in millions)
ASSETS
Current Assets
Cash and cash equivalents		$    30.8
Accounts receivable, net	$   339.8	313.9
Unbilled-gas accounts receivable	57.6	86.9
Fair value of derivative contracts	313.3	128.2
Gas and oil storage	20.5	60.4
Materials and supplies	87.3	94.2
Prepaid expenses and other	37.7	37.8
Regulatory assets	38.1	43.4
Deferred income taxes - current		35.5
Total Current Assets	894.3	831.1
Property, Plant and Equipment (successful efforts method for gas and oil properties)	11,846.4	11,529.9
Accumulated depreciation, depletion and amortization	(3,902.2)	(3,725.0)
Net Property, Plant and Equipment	7,944.2	7,804.9
Investment in unconsolidated affiliates	72.4	72.0
Goodwill	69.9	69.9
Regulatory assets	22.4	23.5
Fair value of derivative contracts	170.4	61.2
Other noncurrent assets	33.8	35.1
TOTAL ASSETS	$9,207.4	$8,897.7
LIABILITIES AND EQUITY
Current Liabilities
Checks outstanding in excess of cash balances	$    10.4
Short-term debt	134.5	$169.0
Accounts payable and accrued expenses	530.5	598.7
Fair value of derivative contracts	139.5	149.7
Regulatory liabilities	10.6	30.7
Deferred income taxes - current	35.8
Current portion of long-term debt	150.0
Total Current Liabilities	1,011.3	948.1
Long-term debt, less current portion	2,029.9	2,179.9
Deferred income taxes	1,638.0	1,553.5
Asset retirement obligations	196.0	189.7
Defined benefit pension plan and other postretirement benefits	210.6	206.9
Fair value of derivative contracts	111.7	140.6
Other long-term liabilities	130.2	121.9
EQUITY
Common stock	462.5	454.8
Retained earnings	3,205.2	3,077.7
Accumulated other comprehensive income (loss)	157.7	(30.3)
Total Common Shareholders' Equity	3,825.4	3,502.2
Noncontrolling interest	54.3	54.9
Total Equity	3,879.7	3,557.1
TOTAL LIABILITIES AND EQUITY	$9,207.4	$8,897.7

See notes accompanying the condensed consolidated financial statements

Questar 2010 Form 10-Q

4

QUESTAR CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	3 Months Ended March 31,
	2010	2009
	(in millions)
OPERATING ACTIVITIES
Net income	$ 150.9	$  67.7
Adjustments to reconcile net income to net cash     provided by operating activities:
Depreciation, depletion and amortization	188.3	163.3
Deferred income taxes	44.6	7.4
Abandonment and impairment	7.6	3.7
Share-based compensation	6.4	5.4
Net (gain) loss from asset sales	0.8	(1.9)
(Income) from unconsolidated affiliates	(1.8)	(1.6)
Distributions from unconsolidated affiliates and other	1.8
Unrealized (gain) loss on basis-only swaps	(34.7)	134.9
Changes in operating assets and liabilities	1.6	101.9
NET CASH PROVIDED BY OPERATING ACTIVITIES	365.5	480.8
INVESTING ACTIVITIES
Property, plant and equipment, including dry exploratory well expense	(349.4)	(390.5)
Cash used in disposition of assets	(0.2)	(0.2)
Proceeds from disposition of assets	0.1	7.1
NET CASH USED IN INVESTING ACTIVITIES	(349.5)	(383.6)
FINANCING ACTIVITIES
Common stock issued	5.9	3.2
Common stock repurchased	(5.9)	(4.0)
Long-term debt issued		50.0
Change in short-term debt	(34.5)	(165.6)
Checks outstanding in excess of cash balances	10.4	16.3
Dividends paid	(22.8)	(21.7)
Tax benefits from share-based compensation	1.3	0.7
Distribution to noncontrolling interest	(1.2)
NET CASH USED IN FINANCING ACTIVITIES	(46.8)	(121.1)
Change in cash and cash equivalents	(30.8)	(23.9)
Beginning cash and cash equivalents	30.8	23.9
Ending cash and cash equivalents	$     -	$     -

See notes accompanying the condensed consolidated financial statements

Questar 2010 Form 10-Q

5

QUESTAR CORPORATION

NOTES ACCOMPANYING THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

Note 1 - Nature of Business

Questar Corporation (Questar or the Company) is a natural gas-focused energy company with five major lines of business - gas and oil exploration and production, midstream field services, energy marketing, interstate gas transportation, and retail gas distribution - which are conducted through its three principal subsidiaries:

Questar Market Resources, Inc. (Market Resources) is a subholding company that operates through four principal subsidiaries. Questar Exploration and Production Company (Questar E&P) acquires, explores for, develops and produces natural gas, oil and NGL. Wexpro Company (Wexpro) manages, develops and produces cost-of-service reserves for gas utility affiliate Questar Gas. Questar Gas Management Company (Gas Management) provides midstream field services including natural gas-gathering and processing services for affiliates and third parties. Questar Energy Trading Company (Energy Trading) markets equity and third-party natural gas and oil, provides risk-management services and owns and operates an underground gas-storage reservoir.

Questar Pipeline Company (Questar Pipeline) provides interstate natural gas transportation and storage and other energy services.

Questar Gas Company (Questar Gas) provides retail natural gas distribution services in Utah, Wyoming and Idaho.

Questar operates in the Rocky Mountain and Midcontinent regions of the United States and is headquartered in Salt Lake City, Utah. Shares of Questar common stock trade on the New York Stock Exchange (NYSE:STR).

Note 2 - Basis of Presentation of Interim Consolidated Financial Statements

The interim condensed consolidated financial statements contain the accounts of Questar and its majority-owned or controlled subsidiaries. The condensed consolidated financial statements were prepared in accordance with U.S. generally accepted accounting principles (GAAP) and with the instructions for quarterly reports on Form 10-Q and Regulations S-X and S-K. All significant intercompany accounts and transactions have been eliminated in consolidation.

The condensed consolidated financial statements reflect all normal, recurring adjustments and accruals that are, in the opinion of management, necessary for a fair presentation of financial position and results of operations for the interim periods presented. Interim condensed consolidated financial statements do not include all of the information and notes required by GAAP for audited annual consolidated financial statements. These condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 2009. Certain reclassifications were made to prior-period financial statements to conform with the current presentation.

The preparation of the condensed consolidated financial statements and notes in conformity with GAAP requires that management make estimates and assumptions that affect the amounts of revenues, expenses, assets and liabilities, and disclosure of contingent assets and liabilities. Actual results could differ from estimates. The results of operations for the three months ended March 31, 2010, are not necessarily indicative of the results that may be expected for the year ending December 31, 2010.

All dollar and share amounts in this quarterly report on Form 10-Q are in millions, except per-share information and where otherwise noted.

Note 3 – Comprehensive Income

Comprehensive income is the sum of net income attributable to Questar as reported in the Consolidated Statements of Income and other comprehensive income (loss). Other comprehensive income (loss) includes changes in the market value of commodity-based derivative instruments and recognition of the under-funded position of pension and other postretirement benefit plans. These transactions are not the culmination of the earnings process but result from periodically adjusting historical balances to fair value. Income or loss is realized when the gas, oil or NGL underlying the derivative instrument is sold or the pension or other postretirement benefit costs are accrued. Comprehensive income (loss) attributable to Questar is shown below:

Questar 2010 Form 10-Q

6

	3 Months Ended March 31,
	2010	2009
	(in millions)
Net income	$150.9	$  67.7
Other comprehensive income
Net unrealized gain on derivatives	299.2	89.6
Other	0.1
Income taxes	(111.3)	(33.4)
Net other comprehensive income	188.0	56.2
Comprehensive income	338.9	123.9
Comprehensive income attributable to noncontrolling interest	(0.6)	(0.5)
Comprehensive income attributable to Questar	$338.3	$123.4

The components of Accumulated Other Comprehensive Income (Loss) (AOCI), net of income taxes, shown on the Condensed Consolidated Balance Sheets are as follows:

	March 31,	December 31,
	2010	2009	Change
	(in millions)
Net unrealized gain on derivatives	$  275.0	$  87.1	$187.9
Pension liability	(104.5)	(104.5)
Postretirement benefits liability	(12.9)	(12.9)
Other	0.1		0.1
Accumulated Other Comprehensive Income (Loss)	$ 157.7	($  30.3)	$188.0

Note 4 - Earnings Per Share (EPS)

Basic EPS is computed by dividing net income attributable to Questar by the weighted-average number of common shares outstanding during the reporting period. Diluted EPS includes the potential increase in the number of outstanding shares that could result from the exercise of in-the-money stock options. A reconciliation of the components of basic and diluted shares used in the EPS calculation follows:

	3 Months Ended March 31,
	2010	2009
	(in millions)
Weighted-average basic common shares outstanding	174.9	173.8
Potential number of shares issuable under the Long-term Stock   Incentive Plan	2.3	2.1
Average diluted common shares outstanding	177.2	175.9

Note 5 - Asset Retirement Obligations

Questar records asset retirement obligations (ARO) when there are legal obligations associated with the retirement of tangible long-lived assets. At Questar, ARO apply primarily to abandonment costs associated with gas and oil wells, production facilities and certain other properties. The fair values of retirement costs are estimated by Company personnel based on abandonment costs of similar properties available to field operations and depreciated over the life of the related assets. Revisions to ARO estimates result from changes in expected cash flows or material changes in estimated retirement costs. The ARO liability is adjusted to present value each period through an accretion calculation using a credit-adjusted risk-free interest rate. Income or expense resulting from the settlement of ARO liabilities is included in net gain or (loss) from asset sales on the Consolidated Statements of Income. Changes in ARO were as follows:

Questar 2010 Form 10-Q

7

	2010	2009
	(in millions)
ARO liability at January 1,	$189.7	$175.6
Accretion	2.7	2.7
Liabilities incurred	11.6	0.8
Revisions	(7.8)	2.4
Liabilities settled	(0.2)	(0.7)
ARO liability at March 31,	$196.0	$180.8

Wexpro collects from Questar Gas and deposits in trust certain funds related to estimated ARO costs. The funds are recorded in other noncurrent assets on the Condensed Consolidated Balance Sheets and used to satisfy retirement obligations as the properties are abandoned. The accounting treatment of reclamation activities associated with ARO for properties administered under the Wexpro Agreement is defined in a guideline letter between Wexpro and the Utah Division of Public Utilities and the staff of the Public Service Commission of Wyoming (PSCW).

Note 6 - Capitalized Exploratory Well Costs

Net changes in capitalized exploratory well costs are presented in the table below and exclude amounts that were capitalized and subsequently expensed in the period. All of these costs have been capitalized for less than one year.

	2010	2009
	(in millions)
Balance at January 1,	$51.7	$17.0
Additions to capitalized exploratory well costs pending the   determination of proved reserves	12.4	8.3
Reclassifications to property, plant and equipment after the   determination of proved reserves	(33.0)	(14.3)
Balance at March 31,	$31.1	$11.0

Note 7 - Fair Value Measurements

Questar measures and discloses fair values in accordance with the provisions of ASC 820 "Fair Value Measurements and Disclosures," formerly SFAS 157. ASC 820 establishes a fair-value hierarchy of Levels 1, 2 and 3 based on inputs with Level 1 measures calculated from the most visible inputs. Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in active markets that the Company has the ability to access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly. Level 3 inputs are unobservable inputs for the asset or liability. The Level 2 fair value of derivative contracts (see Note 8) is based on market prices posted on the NYMEX on the last trading day of the reporting period and industry-standard discounted cash flow models. The Level 3 fair value of derivative contracts is based on NYMEX market prices in combination with unobservable volatility inputs and industry-standard option pricing models. Long-term investments consist of money market and short-term bond index mutual funds, and represent funds held in Wexpro's trust (see Note 5). The fair value of long-term investments is based on quoted prices for the underlying mutual funds, and is considered a Level 1 fair value.

Questar primarily applies the market approach for recurring fair value measurements and maximizes its use of observable inputs and minimizes its use of unobservable inputs. Questar considers bid and ask prices for valuing the majority of its assets and liabilities, measured and reported at fair value. In addition to using market data, Questar makes assumptions in valuing its assets and liabilities, including assumptions about risk and the risks inherent in the inputs to the valuation technique.

Certain of Questar's derivative instruments, however, are valued using industry-standard models that consider various inputs, including quoted forward prices for commodities, time value, volatility, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable prices at which transactions are executed in the marketplace. The determination of fair value for derivative assets and liabilities also incorporates nonperformance risk for counterparties and for Questar. Derivative contract fair values are reported on a net basis to the extent a legal right of offset with a counterparty exists.

Questar did not have any assets or liabilities measured at fair value on a non-recurring basis at March 31, 2010, or at December 31, 2009. The fair value of assets and liabilities at March 31, 2010, is shown in the table below:

Questar 2010 Form 10-Q

8

	Fair Value Measurements March 31, 2010
	Level 1	Level 2	Level 3	Netting Adjustments	Total
	(in millions)
Assets
Long-term investments	$12.2				$  12.2
Derivative contracts - short term		$483.2	$14.6	($184.5)	313.3
Derivative contracts - long term		264.3	16.8	(110.7)	170.4
Total assets	$12.2	$747.5	$31.4	($295.2)	$495.9
Liabilities
Derivative contracts - short term		$323.2	$0.8	($184.5)	$139.5
Derivative contracts - long term		221.0	1.4	(110.7)	111.7
Total liabilities		$544.2	$2.2	($295.2)	$251.2

The change in the fair value of Level 3 assets and liabilities for the first quarter of 2010 is shown below:

	Derivative Contracts
	2010
	(in millions)
Balance at January 1,	$ 5.5
Realized gains and losses included in revenues	0.6
Unrealized gains and losses included in other comprehensive income	23.7
Settlements	(0.6)
Balance at March 31,	$29.2

The fair value of assets and liabilities at December 31, 2009, is shown in the table below:

	Fair Value Measurements December 31, 2009
	Level 1	Level 2	Level 3	Netting Adjustments	Total
	(in millions)
Assets
Long-term investments	$11.7				$  11.7
Derivative contracts - short term		$312.6	$ 2.4	($186.8)	128.2
Derivative contracts - long term		194.3	16.1	(149.2)	61.2
Total assets	$11.7	$506.9	$18.5	($336.0)	$201.1
Liabilities
Derivative contracts - short term		$334.4	$ 2.1	($186.8)	$149.7
Derivative contracts - long term		278.9	10.9	(149.2)	140.6
Total liabilities		$613.3	$13.0	($336.0)	$290.3

The following table discloses the fair value and related carrying amount of certain financial instruments not disclosed in other notes to the consolidated financial statements in this quarterly report on Form 10-Q:

Questar 2010 Form 10-Q

9

	Carrying	Estimated	Carrying	Estimated
	Amount	Fair Value	Amount	Fair Value
	March 31, 2010		December 31, 2009
	(in millions)
Financial assets
Cash and cash equivalents			$    30.8	$    30.8
Financial liabilities
Checks outstanding in excess of cash balances	$    10.4	$    10.4
Short-term debt	134.5	134.5	169.0	169.0
Long-term debt	2,179.9	2,389.6	2,179.9	2,289.2

The carrying amounts of cash and cash equivalents, checks outstanding in excess of cash balances and short-term debt approximate fair values. The fair value of fixed-rate long-term debt is based on the discounted present value of cash flows using the Company's current credit-risk adjusted borrowing rates. The carrying amount of variable-rate long-term debt approximates fair value.

Note 8 - Derivative Contracts

Market Resources’ subsidiaries use commodity-price derivative instruments in the normal course of business. Market Resources has established policies and procedures for managing commodity-price risks through the use of derivative instruments. Market Resources uses derivative instruments to support rate of return and cash flow targets and protect earnings from downward movements in commodity prices. However, these same instruments typically limit future gains from favorable price movements. Derivative contracts are currently in place for a significant share of Questar E&P-owned gas and oil production and a portion of Energy Trading gas marketing transactions. The volume of production with associated derivative instruments and the mix of the instruments are frequently evaluated and adjusted by management in response to changing market conditions. Market Resources may match derivative contracts with up to 100% of forecast production from proved reserves when prices meet earnings and cash flow objectives. Market Resources does not enter into derivative instruments for speculative purposes.

Market Resources uses derivative instruments known as fixed-price swaps and costless collars to realize a known price or range of prices for a specific volume of production delivered into a regional sales point. Swap agreements do not require the physical transfer of natural gas between the parties at settlement. Swap transactions are settled in cash with one party paying the other for the net difference in prices, multiplied by the relevant volume, for the settlement period. Collars are combinations of put and call options that have a floor price and a ceiling price and are only triggered if the settlement price is outside the range of the floor and ceiling prices. In the past, Questar E&P has also used natural gas basis-only swaps to protect cash flows and net income from widening natural gas-price basis differentials. However, natural gas basis-only swaps exposed the company to losses from narrowing natural gas price-basis differentials. As of December 31, 2009, all of the company's basis-only swaps were paired with fixed-price swaps and re-designated as cash flow hedges. Changes in the fair value of the derivative instruments subsequent to the re-designation were recorded in AOCI. Fair value changes occurring prior to re-designation were recorded in income.

Market Resources enters into derivative instruments that do not have margin requirements or collateral provisions that would require funding prior to the scheduled cash settlement dates. Derivative-arrangement counterparties are normally financial institutions and energy-trading firms with investment-grade credit ratings. Market Resources routinely monitors and manages its exposure to counterparty risk by requiring specific minimum credit standards for all counterparties and transacting with multiple counterparties.

All derivative instruments are required to be recorded on the balance sheet as either assets or liabilities measured at their fair values. The designation of a derivative instrument as a hedge and its ability to meet hedge accounting criteria determines how the change in fair value of the derivative instrument is reflected in the consolidated financial statements. A derivative instrument qualifies for hedge accounting, if at inception, the derivative is expected to be highly effective in offsetting the underlying hedged cash flows. Generally, Market Resources' derivative instruments are matched to equity gas and oil production and are highly effective, thus qualifying as cash flow hedges. Changes in the fair value of effective cash flow hedges are recorded as a component of AOCI on the Condensed Consolidated Balance Sheets and reclassified to earnings as gas and oil sales when the underlying physical transactions occur. Gas hedges are typically structured as fixed-price swaps into regional pipelines, locking in basis and hedge effectiveness. Costless collars qualify for cash flow hedge accounting. A basis-only swap does not qualify for hedge accounting treatment. Market Resources regularly reviews the effectiveness of derivative instruments. The ineffective portion of cash flow hedges and the mark to market adjustment of basis-only swaps are recognized in the determination of net income.

Questar 2010 Form 10-Q

10

	3 Months Ended March 31,
	2010	2009
	(in millions)
Effect of derivative instruments designated as cash flow hedges
Gains recognized in AOCI for the effective portion of hedges	$344.6	$247.5
Gains (losses) reclassified from AOCI into income for the effective portion of hedges
Revenues	$43.6	$158.5
Cost of natural gas and other products sold	1.8	(0.6)
(Losses) recognized in income for the ineffective portion of hedges
Interest and other income	(0.5)
Effect of derivative instruments not designated as hedges
Unrealized gain (loss) on basis-only swaps	34.7	(134.9)
Realized (loss) on basis-only swaps	(34.7)	(3.4)

Based on March 31, 2010 prices, $182.3 million will be settled and reclassified from AOCI to the Consolidated Statements of Income in the next 12 months. The following table discloses the fair value of derivative contracts on a gross-contract basis as opposed to the net-contract basis presentation in the Condensed Consolidated Balance Sheets.

		March 31, 2010	December 31, 2009
		(in millions)
Fixed-price swaps		$483.2	$312.6
Option contracts		14.6	2.4
Fair value of derivative instruments - short term		$497.8	$315.0
Fixed-price swaps		$264.3	$194.3
Option contracts		16.8	16.1
Fair value of derivative instruments - long term		$281.1	$210.4
Liabilities
Fixed-price swaps		$205.0	$212.7
Option contracts		0.8	2.1
Basis-only swaps		118.2	121.7
Fair value of derivative instruments - short term		$324.0	$336.5
Fixed-price swaps		$134.5	$161.2
Option contracts		1.4	10.9
Basis-only swaps		86.5	117.7
Fair value of derivative instruments - long term		$222.4	$289.8

Previously reported basis-only swaps have been combined with fixed-price NYMEX natural gas swaps for 2010 and 2011 and now qualify as cash flow hedges. The following table sets forth Market Resources' volumes and average net-to-the-well prices for transactions with associated risk management derivative contracts as of March 31, 2010:

Questar 2010 Form 10-Q

11

Questar E&P Production

Year	Time Periods	Quantity	Average hedge price per Mcf or Bbl, net to the well(a)
			(estimated)
Gas (Bcf) Fixed-price Swaps
2010	9 months	113.7	$5.26
2011	12 months	102.1	4.91
2012	12 months	40.6	5.91
2013	12 months	47.2	5.98
Gas (Bcf) Collars
			Floor- Ceiling
2010	9 months	5.0	$4.65 - $6.51
2011	12 months	27.7	4.63 -   6.66
Oil (Mbbl) Fixed-price Swaps
2010	9 months	688	$60.66
Oil (Mbbl) Collars
			Floor- Ceiling
2010	9 months	550	$47.60 - $96.10
2011	12 months	1,095	51.73 - 102.10

Energy Trading Marketing Transactions

Year	Time Periods	Quantity	Average hedged price  per MMBtu
Gas Sales (millions of MMBtu) Fixed-price Swaps
2010	9 months	4.9	$5.10
2011	12 months	0.8	6.15

Gas Purchases (millions of MMBtu) Fixed-price Swaps
2010	9 months	2.4	$4.56
2011	12 months	0.3	6.20

(a)

The fixed-price swap and collar prices are reduced by gathering costs and adjusted for product quality to determine the net-to-the-well price.

Note 9 - Share-Based Compensation

Questar issues stock options and restricted shares to certain officers, employees and non-employee directors under its Long-Term Stock Incentive Plan (LTSIP) and recognizes expense over time as the stock options or restricted shares vest. First quarter share-based compensation expense amounted to $6.4 million in 2010 compared to $5.4 million in 2009. Deferred share-based compensation, representing the unvested value of restricted share awards, amounted to $26.1 million at March 31, 2010, compared to $13.7 million at December 31, 2009. Deferred share-based compensation is included in common stock on the Condensed Consolidated Balance Sheets. First quarter cash flow from income tax benefits in excess of recognized compensation expense amounted to $1.3 million in 2010 compared to $0.7 million in 2009. There were 7,379,847 shares available for future grant at March 31, 2010.

The Company uses the Black-Scholes-Merton mathematical model in estimating the fair value of stock options for accounting purposes. Fair-value calculations rely upon subjective assumptions used in the mathematical model and may not be representative of future results. The Black-Scholes-Merton model was intended for measuring the value of options traded on an exchange. The calculated fair value of options granted and major assumptions used in the model at the date of grant are listed below:

Questar 2010 Form 10-Q

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	Stock Option Variables 3 Months Ended March 31, 2010
Fair value of options at grant date	$40.65
Risk-free interest rate	2.30%
Expected price volatility	30.3%
Expected dividend yield	1.18%
Expected life in years	5.2

Unvested stock options decreased by 288,682 to 1,388,645 in the first quarter of 2010. Stock-option transactions under the terms of the LTSIP are summarized below:

	Options Outstanding	Price Range	Weighted- average Price
Balance at January 1, 2010	4,655,493	$  7.50 - $53.83	$21.99
Granted	451,000	40.65	40.65
Exercised	(107,908)	7.50 - $14.01	9.57
Balance at March 31, 2010	4,998,585	$11.48 - $53.83	$23.94

Options Outstanding				Options Exercisable		Unvested Options
Range of exercise prices	Number outstanding at March 31, 2010	Weighted-average remaining term in years	Weighted-average exercise price	Number exercisable at March 31, 2010	Weighted-average exercise price	Number unvested at March 31, 2010	Weighted- average exercise price
$11.48 –  11.98	855,488	1.8	$11.58	855,488	$11.58
13.56  -   17.55	1,790,597	2.1	13.74	1,790,597	13.74
24.33 -   38.57	1,731,500	5.1	34.35	860,521	34.97	870,979	$33.75
$40.65 - $53.83	621,000	6.4	41.38	103,334	42.31	517,666	41.20
	4,998,585	3.6	$23.94	3,609,940	$19.10	1,388,645	$36.52

Restricted-share grants typically vest in equal installments over a three- or four-year period from the grant date. Several grants vest in a single installment after a specified period. The weighted-average vesting period of unvested restricted shares at March 31, 2010, was 20 months. Transactions involving restricted shares under the terms of the LTSIP are summarized below:

	Unvested Restricted Shares	Price Range	Weighted-average Price
Balance at January 1, 2010	880,860	$25.12 - $70.13	$43.44
Granted	428,800	40.65 – 42.58	40.69
Distributed	(286,068)	29.30 – 57.47	42.90
Forfeited	(6,564)	35.23 – 64.22	42.31
Balance at March 31, 2010	1,017,028	$25.12 – $70.13	$42.44

Note 10 - Employee Benefits

The Company has defined-benefit pension and life insurance plans covering a majority of its employees and a postretirement medical plan providing coverage to less than half of its employees. Questar is subject to and complies with minimum-required and maximum-allowed annual contribution levels for its qualified retirement plan as determined by the Employee Retirement Income Security Act and Internal Revenue Code. Subject to these limitations, Questar plans to fund the qualified retirement plan in amounts approximately equal to the yearly expense, which is estimated to be $21.9 million for 2010. Pension expense increased year-over-year because returns on plan assets were lower than expected.

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The Company also has a nonqualified pension plan for eligible employees, which provides a benefit in addition to the benefit limit defined by the Internal Revenue Service for qualified pension plans. The nonqualified pension plan is unfunded. Claims are paid from the Company general funds. The 2010 nonqualified pension plan expense is estimated to be $2.8 million.

Components of the qualified and nonqualified pension expense included in the determination of net income are listed below:

	3 Months Ended March 31,
	2010	2009
	(in millions)
Service cost	$ 2.4	$ 2.5
Interest cost	7.9	7.2
Expected return on plan assets	(6.4)	(6.4)
Prior service and other costs	0.3	0.3
Recognized net-actuarial loss	1.8	1.5
Settlement costs	0.2	0.3
Pension expense	$ 6.2	$ 5.4

The Company currently estimates a $6.1 million expense for postretirement benefits other than pensions in 2010 before $0.8 million for accretion of a regulatory liability. Postretirement benefits include an estimate of the effect of the Medicare Prescription Drug, Improvement and Modernization Act of 2003. Questar's prescription drug benefit is actuarially equivalent to Part D of Medicare and; therefore, qualifies for a federal subsidy available on benefits provided to plan participants. In 2004, the Medicare Part D benefit reduced the accumulated postretirement benefit obligation by $2.0 million. By year-end 2009, the Medicare Part D subsidy grew to $4.0 million. Yearly amortization of this benefit amounting to $0.3 million reduces expense through a decrease in the amortization of the unrecognized net loss. The Medicare Part D subsidy is no longer tax exempt as a result of the Health Care and Education Reconciliation Act of 2010. Receipts of Medicare Part D subsidies reduce Company contributions to the employee plan. Expense components are listed below:

	3 Months Ended March 31,
	2010	2009
	(in millions)
Service cost	$ 0.2	$ 0.2
Interest cost	1.2	1.2
Expected return on plan assets	(0.5)	(0.5)
Amortization of transition obligation	0.5	0.5
Amortization of losses	0.2	0.3
Accretion of regulatory liability	0.2	0.2
Postretirement benefits expense	$ 1.8	$ 1.9

Note 11 - Operations by Line of Business

Questar's major lines of business include gas and oil exploration and production (Questar E&P and Wexpro), midstream field services (Gas Management), energy marketing (Energy Trading), interstate gas transportation (Questar Pipeline), and retail gas distribution (Questar Gas). Line-of-business information is presented according to senior management's basis for evaluating performance considering differences in the nature of products, services and regulation among other factors. Following is a summary of operations by line of business:

	3 Months Ended March 31,
	2010	2009
	(in millions)
Revenues from Unaffiliated Customers
Questar E&P	$319.7	$310.8
Wexpro	6.2	2.4
Gas Management	74.2	48.3
Energy Trading and other	176.2	114.6

Questar 2010 Form 10-Q

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Market Resources	576.3	476.1
Questar Pipeline	47.0	40.7
Questar Gas	360.7	405.7
Total	$984.0	$922.5
Revenues from Affiliated Companies
Wexpro	$ 60.5	$  59.5
Gas Management	6.7	6.7
Energy Trading and other	147.4	93.2
Market Resources	214.6	159.4
Questar Pipeline	19.5	19.1
Questar Gas	0.3
Total	$234.4	$178.5
Operating Income (Loss)
Questar E&P	$103.8	$127.2
Wexpro	32.8	28.9
Gas Management	37.1	19.6
Energy Trading and other	2.0	8.3
Market Resources	175.7	184.0
Questar Pipeline	33.5	29.3
Questar Gas	58.6	57.2
Corporate	(0.1)
Total	$267.7	$270.5
Net Income (Loss) Attributable to Questar
Questar E&P	$ 53.8	($14.9)
Wexpro	21.2	18.8
Gas Management	23.2	11.4
Energy Trading and other	1.1	5.4
Market Resources	99.3	20.7
Questar Pipeline	17.2	14.7
Questar Gas	33.1	31.8
Corporate	0.7
Total	$150.3	$67.2

Note 12 - Questar Considering Spinoff of Market Resources Excluding Wexpro

On April 21, 2010, Questar Corporation announced it is considering a possible tax-free spinoff of Market Resources and its subsidiaries excluding Wexpro. After the spinoff, Questar Corporation would remain an integrated natural gas company comprised of subsidiaries Wexpro, Questar Pipeline, and Questar Gas. On April 28, 2010, the Internal Revenue Service, in a private letter ruling, confirmed that the proposed spinoff would be a tax-free transaction. Receipt of the referenced private letter ruling is among several precedent conditions to consummation of the proposed spin transaction, including board approval. Subject to those precedent conditions, the spinoff transaction may occur in the second half of 2010.

On April 22, 2010, Moody's Investors Service placed its Baa3 rating of Market Resources' long-term debt under review for possible downgrade and Standard & Poor's placed its BBB+ rating of Market Resources' long-term debt on CreditWatch with negative implications. Moody's affirmed its A3 rating of long-term debt issued by Questar Pipeline and Questar Gas and Standard & Poor's placed the BBB+ ratings of long-term debt issued by Questar Pipeline and Questar Gas on CreditWatch with positive implications. Moody's affirmed its P-2 rating of Questar's short-term debt and Standard & Poor's placed its A-2 rating on Questar's short-term debt on CreditWatch with positive implications.

Questar 2010 Form 10-Q

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Note 13 – Questar Gas General Rate Case

On April 8, 2010, the Public Service Commission of Utah (PSCU) approved a stipulated settlement of Questar Gas's Utah general rate case. The settlement increases Questar Gas's allowed return on equity from 10.0% to 10.35% and extends the existing conservation enabling tariff (CET). The settlement also provides for a rate-tracking mechanism to allow for recovery of the capital costs associated with Questar Gas's high-pressure natural gas feeder-line replacement program.

ITEM 2.  MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

The following information updates the discussion of Questar's financial condition provided in its 2009 Form 10-K filing, and analyzes the changes in the results of operations between the quarters ended March 31, 2010, and 2009. For definitions of commonly used gas and oil terms found in this report on Form 10-Q, please refer to the "Glossary of Commonly Used Terms" provided in Questar's 2009 Form 10-K.

RESULTS OF OPERATIONS

Following are comparisons of net income (loss) attributable to Questar by line of business:

	3 Months Ended March 31,
	2010	2009	Change
	(in millions, except per share amounts)
Exploration and Production
Questar E&P	$  53.8	($14.9)	$68.7
Wexpro	21.2	18.8	2.4
Midstream Field Services – Gas Management	23.2	11.4	11.8
Energy Marketing – Energy Trading and other	1.1	5.4	(4.3)
Market Resources total	99.3	20.7	78.6
Interstate Gas Transportation – Questar Pipeline	17.2	14.7	2.5
Retail Gas Distribution – Questar Gas	33.1	31.8	1.3
Corporate	0.7		0.7
Net income attributable to Questar	$150.3	$67.2	$83.1
Earnings per diluted share	$0.85	$0.38	$0.47
Average diluted shares	177.2	175.9	1.3

EXPLORATION AND PRODUCTION

Questar E&P

Questar E&P reported net income of $53.8 million in the first quarter of 2010 compared with a loss of $14.9 million in the 2009 quarter. Higher realized crude oil and NGL prices and a 10% increase in 2010 production largely offset lower realized natural gas prices. Changes in unrealized basis-only swaps increased net income $21.8 million in the 2010 quarter compared to a loss of $84.7 million in the year-earlier period. Following is a summary of Questar E&P financial and operating results:

	3 Months Ended March 31,
	2010	2009	Change
	(in millions)
Operating Income
Revenues
Natural gas sales	$264.6	$278.4	($ 13.8)
Oil and NGL sales	54.0	31.1	22.9
Other	1.1	1.3	(0.2)
Total Revenues	319.7	310.8	8.9
Operating expenses
Operating and maintenance	28.8	34.4	(5.6)
General and administrative	19.1	15.6	3.5
Production and other taxes	21.7	15.4	6.3

Questar 2010 Form 10-Q

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Depreciation, depletion and amortization	135.1	113.3	21.8
Exploration	3.6	3.1	0.5
Abandonment and impairment	7.6	3.7	3.9
Total Operating Expenses	215.9	185.5	30.4
Net gain from asset sales		1.9	(1.9)
Operating Income	$103.8	$127.2	($ 23.4)
Unrealized gain (loss) on basis-only swaps	$   34.7	($134.9)	$169.6
Realized (loss) on basis-only swaps	($   34.7)	($3.4)	($ 31.3)
Operating Statistics
Production volumes
Natural gas (Bcf)	46.3	41.4	4.9
Oil and NGL (MMbbl)	0.9	0.9
Total production (Bcfe)	51.5	46.9	4.6
Average daily production (MMcfe)	572.3	521.3	51.0
Average realized price, net to the well (including hedges)
Natural gas (per Mcf)	$5.72	$ 6.72	($1.00)
Oil and NGL (per bbl)	61.80	34.09	27.71

Questar E&P reported production of 51.5 Bcfe in the first quarter of 2010 compared to 46.9 Bcfe in the 2009 quarter, a 10% increase. Natural gas is Questar E&P's primary focus. On an energy-equivalent basis, natural gas comprised approximately 90% of Questar E&P 2010 production. A summary of natural gas-equivalent production by major operating area is shown in the following table:

	3 Months Ended March 31,
	2010	2009	Change
	(in Bcfe)
Midcontinent	26.2	21.0	5.2
Pinedale Anticline	15.5	14.6	0.9
Uinta Basin	5.2	6.3	(1.1)
Rockies Legacy	4.6	5.0	(0.4)
Total Questar E&P	51.5	46.9	4.6

Questar E&P production increased 10% in the first quarter of 2010 compared to a year earlier. In the Midcontinent, production grew 25% to 26.2 Bcfe in the first quarter of 2010. Ongoing development drilling in the Haynesville Shale play in northwest Louisiana and the Woodford Shale play in the Anadarko Basin of western Oklahoma were the main contributors to the production increase. Questar E&P production from the Pinedale Anticline in western Wyoming grew 6% to 15.5 Bcfe in the first quarter of 2010 as a result of ongoing development drilling. In the Uinta Basin, production decreased 17% to 5.2 Bcfe in the first quarter of 2010 due to decreased drilling activity. Questar E&P Rockies Legacy production decreased 8% to 4.6 Bcfe in the first quarter of 2010. Rockies Legacy properties include all of Questar E&P's Rocky Mountain region properties except the Pinedale Anticline and the Uinta Basin.

Realized prices for natural gas were lower when compared to the prior year, while realized oil and NGL prices at Questar E&P were higher when compared to the prior-year period. In the first quarter 2010, the weighted-average realized natural gas price for Questar E&P, including the impact of hedging, was $5.72 per Mcf compared to $6.72 per Mcf for the same period in 2009, a 15% decrease. Realized oil and NGL prices in the first quarter of 2010 averaged $61.80 per bbl, compared with $34.09 per bbl during the prior year period, an 81% increase. A regional comparison of average realized prices, including hedges, is shown in the following table:

	3 Months Ended March 31,
	2010	2009	Change
Natural gas (per Mcf)
Midcontinent	$6.45	$7.53	($1.08)
Rocky Mountains	4.91	6.05	(1.14)
Volume-weighted average	5.72	6.72	(1.00)

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Oil and NGL (per bbl)
Midcontinent	$62.21	$36.90	$25.31
Rocky Mountains	61.55	32.01	29.54
Volume-weighted average	61.80	34.09	27.71

Questar E&P net realized natural gas prices, including realized losses on basis-only swaps, at Questar E&P averaged $4.97 per Mcf, down 25% compared to the first quarter of 2009. A comparison of net realized average natural gas prices is shown in the following table:

	3 Months Ended March 31,
	2010	2009	Change
Natural gas (per Mcf)
Volume-weighted average (a)	$5.72	$6.72	($1.00)
Realized losses on basis-only swaps (b)	(0.75)	(0.08)	(0.67)
Net realized natural gas price ($ per Mcf)	$4.97	$6.64	($1.67)

(a)

Reported in revenues in the Consolidated Income Statement.

(b)

Reported after operating income in the Consolidated Income Statement.

Questar E&P hedged approximately 80% of first quarter 2010 gas production with fixed price swaps, and 4% with collars. In first quarter 2009, approximately 77% of gas production was hedged with fixed price swaps. An additional 15% of gas production was subject to basis-only swaps in the 2009 quarter. Gas hedging increased Questar E&P first quarter 2010 gas revenues by $45.6 million and first quarter 2009 gas revenues by $139.8 million. Approximately 33% of first quarter 2010 oil production was hedged with fixed price swaps, and 27% with collars. In first quarter 2009, approximately 25% of oil production was hedged with fixed price swaps. Oil hedges decreased revenues $2.0 million in 2010 and increased revenues $4.6 million in 2009. The net effect of natural gas-basis-only swaps is reported in the Consolidated Statements of Income below operating income. Derivative positions as of March 31, 2010, are summarized in Note 8 to the consolidated financial statements in Item 1 of Part I in this Quarterly Report on Form 10-Q.

Questar E&P production costs (the sum of depreciation, depletion and amortization expense, lease operating expense, general and administrative expense, allocated interest expense and production taxes) per Mcfe of production increased 5% to $4.34 per Mcfe in 2010 versus $4.12 per Mcfe in 2009. Questar E&P production costs are summarized in the following table:

	3 Months Ended March 31,
	2010	2009	Change
	(per Mcfe)
Depreciation, depletion and amortization	$2.62	$2.42	$0.20
Lease operating expense	0.56	0.73	(0.17)
General and administrative expense	0.37	0.33	0.04
Allocated interest expense	0.37	0.31	0.06
Production taxes	0.42	0.33	0.09
Total Production Costs	$4.34	$4.12	$0.22

Production volume-weighted average depreciation, depletion and amortization (DD&A) expense per Mcfe increased in 2010 due to the ongoing depletion of older, lower-cost reserves and the increasing share of Questar E&P production derived from properties with higher DD&A rates. Lease operating expense per Mcfe decreased as the result of increased production combined with lower operating expense. Growing production from new high-rate, low operating cost wells in northwest Louisiana and declining production from higher-cost areas is lowering average lease operating expense. General and administrative expense per Mcfe increased due primarily to increased labor and legal expense. Allocated interest expense per unit of production increased in the 2010 period primarily due to higher debt balances. Production taxes per Mcfe increased in the first quarter of 2010 as a result of higher natural gas and oil field-level sales prices.

Questar E&P exploration expense increased $0.5 million or 16% in the first quarter of 2010 compared to 2009. Abandonment and impairment expense increased $3.9 million, or 105% in 2010 compared to 2009.

The Company has used basis-only swaps to manage the risk of widening basis differentials. Basis-only swaps do not qualify for hedge accounting. The change in unrealized gains and losses on natural gas basis-only swaps increased first quarter 2010 net

Questar 2010 Form 10-Q

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income $21.8 million compared to a loss of $84.7 million in the year-earlier period. As of December 31, 2009, all of the Company's basis-only swaps were paired with fixed-price swaps and re-designated as cash flow hedges. Changes in the fair value of the derivative instruments subsequent to the re-designation were recorded in AOCI. Fair value changes occurring prior to re-designation were recorded in income.

Major Questar E&P Operating Areas

Midcontinent

Questar E&P Midcontinent properties are distributed over a large area, including the Anadarko Basin of Oklahoma and the Texas Panhandle, the Arkoma Basin of Oklahoma and western Arkansas, and the Ark-La-Tex region of Arkansas, Louisiana, and Texas. With the exception of northwest Louisiana, the Granite Wash play in the Texas Panhandle and the Woodford Shale play in western Oklahoma, Questar E&P Midcontinent leasehold interests are fragmented, with no significant concentration of property interests.

Questar E&P has approximately 48,000 net acres of Haynesville Shale lease rights in northwest Louisiana. The depth of the top of the Haynesville Shale ranges from approximately 10,500 feet to 12,500 feet across Questar E&P's leasehold and is below the Hosston and Cotton Valley formations that Questar E&P has been developing in northwest Louisiana for over a decade. Questar E&P continues infill-development drilling in the Hosston and Cotton Valley formations in northwest Louisiana and intends to drill or participate in up to 35 horizontal Haynesville Shale wells in 2010. As of March 31, 2010, Questar E&P had six operated rigs drilling in the project area and operated or had working interests in 628 producing wells in northwest Louisiana compared to 554 at March 31, 2009.

Pinedale Anticline

As of March 31, 2010, Market Resources (including both Questar E&P and Wexpro) operated and had working interests in 437 producing wells on the Pinedale Anticline compared to 337 at the end of the first quarter of 2009. Of the 437 producing wells, Questar E&P has working interests in 415 wells, overriding royalty interests in an additional 21 Wexpro-operated wells, and no interest in one well operated by Wexpro. Wexpro has working interests in 126 of the 437 producing wells.

In 2005, the Wyoming Oil and Gas Conservation Commission (WOGCC) approved 10-acre-density drilling for Lance Pool wells on about 12,700 acres of Market Resources' 17,872-acre (gross) Pinedale leasehold. The area approved for increased density corresponds to the currently estimated productive limits of Market Resources core acreage in the field. The company continues to evaluate development on five-acre density at Pinedale. In January 2008, the WOGCC approved five-acre-density drilling for Lance Pool wells on about 4,200 gross acres of Market Resources Pinedale leasehold. If five-acre-density development is appropriate for a majority of its leasehold, the company currently estimates up to 1,400 additional wells will be required to fully develop the Lance Pool on its acreage.

Uinta Basin

As of March 31, 2010, Questar E&P had an operating interest in 2,327 producing wells in the Uinta Basin of eastern Utah, compared to 888 at March 31, 2009. The significant increase in well count was due to the inclusion of Questar E&P acreage within the outside-operated Greater Monument Butte enhanced recovery unit in 2009; resulting in Questar E&P having a very small interest in 1,313 wells. Uinta Basin proved reserves are found in a series of vertically stacked, laterally discontinuous reservoirs at depths of 5,000 feet to deeper than 18,000 feet. Questar E&P owns interests in over 420,000 gross leasehold acres in the Uinta Basin.

Rockies Legacy

The remainder of Questar E&P Rocky Mountain region leasehold interests, productive wells and proved reserves are distributed over a number of fields and properties managed as the Rockies Legacy division. Most of the properties are located in the Greater Green River Basin of western Wyoming. Planned exploration and development activity for 2010 includes wells in the Green River Basin and the Williston Basin in North Dakota.

Wexpro

Wexpro reported net income of $21.2 million in the first quarter of 2010 compared to $18.8 million in 2009, a 13% increase. Wexpro 2010 results benefited from a higher average investment base compared to the prior-year period. Pursuant to the Wexpro Agreement, Wexpro recovers its costs and receives an unlevered after-tax return of approximately 19-20% on its investment base. Wexpro’s investment base is its investment in commercial wells and related facilities adjusted for working capital and reduced for deferred income taxes and depreciation. Wexpro’s investment base totaled $427.8 million at March 31, 2010, an increase of $27.7 million or 7% since March 31, 2009. Wexpro produced 13.0 Bcf of cost-of-service gas in the 2010 quarter.

MIDSTREAM FIELD SERVICES - Gas Management

Gas Management, which provides gas-gathering and processing-services, reported net income of $23.2 million in the first quarter of 2010 compared to $11.4 million in the same period of 2009. The increase in net income was driven by higher gas-gathering and processing margins. Following is a summary of Gas Management financial and operating results:

Questar 2010 Form 10-Q

19

	3 Months Ended March 31,
	2010	2009	Change
	(in millions)
Operating Income
Revenues
Gathering	$36.0	$32.0	$  4.0
Processing	34.2	18.4	15.8
Other gathering	10.7	4.6	6.1
Total Revenues	80.9	55.0	25.9
Operating expenses
Operating and maintenance	23.3	19.6	3.7
General and administrative	6.8	3.8	3.0
Production and other taxes	1.1	0.9	0.2
Depreciation, depletion and amortization	11.8	10.9	0.9
Total Operating Expenses	43.0	35.2	7.8
Net (loss) from asset sales	(0.8)	(0.2)	(0.6)
Operating Income	$37.1	$19.6	$17.5
Operating Statistics
Natural gas processing volumes
NGL sales (MMgal)	24.8	21.4	3.4
NGL sales price (per gal)	$1.04	$0.47	$0.57
Fee-based processing volumes (in millions of MMBtu)
For unaffiliated customers	26.2	24.8	1.4
For affiliated customers	27.5	27.7	(0.2)
Total Fee-Based Processing Volumes	53.7	52.5	1.2
Fee-based processing (per MMBtu)	$0.15	$0.16	($0.01)
Natural gas gathering volumes (in millions of MMBtu)
For unaffiliated customers	58.8	65.1	(6.3)
For affiliated customers	54.9	44.9	10.0
Total Gas Gathering Volumes	113.7	110.0	3.7
Gas gathering revenue (per MMBtu)	$0.32	$0.29	$0.03

Gathering margin (gathering revenue minus gathering operating and maintenance expense) increased 41% to $36.8 million in 2010 compared to $26.1 million in 2009. Gathering volumes increased 3.7 million MMBtu, or 3% to 113.7 million MMBtu in 2010.

Processing margin (processing revenue minus plant operating and maintenance expense, which includes processing plant-shrink) increased 124% to $20.8 million in 2010 compared to $9.3 million in 2009. Fee-based gas processing volumes were 53.7 million MMBtu in 2010, a 2% increase compared to 2009. In 2010, fee-based gas processing revenues increased 1% or $0.1 million, while the frac spread from keep-whole processing increased 343% or $12.0 million.

Approximately 78% of Gas Management's net operating revenue from processing and gathering contracts (revenue minus processing plant-shrink) in 2010 was derived from fee-based contracts, down from 93% in 2009.

Depreciation expense grew $0.9 million or 8% in the first quarter of 2010 compared with the 2009 quarter as the result of plant additions.

ENERGY MARKETING - Energy Trading

Energy Trading net income was $1.1 million in 2010, a decrease of 80% compared to $5.4 million in 2009 as a result of lower marketing margin. Revenues from unaffiliated customers were $176.2 million in 2010 compared to $114.6 million in 2009, a 54%

Questar 2010 Form 10-Q

20

increase. The weighted-average natural gas sales price increased 34% in 2010 to $5.05 per MMBtu, compared to $3.78 per MMBtu in 2009.

INTERSTATE GAS TRANSPORTATION – Questar Pipeline

Questar Pipeline, which provides interstate natural gas-transportation and storage services, reported first quarter 2010 net income of $17.2 million compared with $14.7 million in 2009, a 17% increase. Operating income increased $4.2 million, or 14%, in the first quarter 2010-to-2009 comparison due primarily to higher transportation and NGL sales. Following is a summary of Questar Pipeline financial and operating results:

	3 Months Ended March 31,
	2010	2009	Change
	(in millions)
Operating Income
Revenues
Transportation	$47.0	$42.7	$4.3
Storage	9.5	9.6	(0.1)
NGL sales	5.1	1.8	3.3
Energy services	3.4	4.0	(0.6)
Gas processing	0.5	0.9	(0.4)
Other	1.0	0.8	0.2
Total Revenues	66.5	59.8	6.7
Operating expenses
Operating and maintenance	7.8	8.1	(0.3)
General and administrative	10.6	8.6	2.0
Depreciation and amortization	11.8	10.8	1.0
Other taxes	2.4	2.3	0.1
Cost of goods sold	0.5	0.8	(0.3)
Total Operating Expenses	33.1	30.6	2.5
Net gain from asset sales	0.1	0.1
Operating Income	$33.5	$29.3	$4.2
Operating Statistics
Natural gas-transportation volumes (MMdth)
For unaffiliated customers	154.2	153.9	0.3
For Questar Gas	44.0	44.4	(0.4)
For other affiliated customers	1.5	1.2	0.3
Total Transportation	199.7	199.5	0.2
Transportation revenue (per dth)	$0.24	$0.21	$0.03
Firm daily transportation demand at March 31, (including   White River Hub of 1,020 in 2010 and 1,005 in 2009) in Mdth	4,683	4,219	464
Natural gas processing
NGL sales (MMgal)	3.4	3.0	0.4
NGL sales price (per gal)	$1.49	$0.59	$0.90

Revenues

As of March 31, 2010, Questar Pipeline had firm-transportation contracts of 4,683 Mdth per day, including 1,020 Mdth per day from Questar Pipeline’s 50% ownership of White River Hub, compared with 4,219 Mdth per day as of March 31, 2009. Questar Pipeline has expanded its transportation system in response to growing regional natural gas production and transportation demand. The increase in transportation revenues was due primarily to an expansion of the Overthrust Pipeline system that was completed in the fourth quarter of 2009. The company has long-term firm-transportation contracts of 460 Mdth per day associated with this expansion.

Questar Gas is Questar Pipeline’s largest transportation customer with contracts for 901 Mdth per day. The majority of the Questar Gas transportation contracts extend through mid 2017.

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Questar Pipeline owns and operates the Clay Basin underground storage complex in eastern Utah. This facility is 100% subscribed under long-term contracts. In addition to Clay Basin, Questar Pipeline also owns and operates three smaller aquifer gas storage facilities. Questar Gas has contracted for 26% of firm-storage capacity at Clay Basin for terms extending from three to nine years and 100% of the firm-storage capacity at the aquifer facilities for terms extending for eight years.

Questar Pipeline charges FERC-approved transportation and storage rates that are based on straight-fixed-variable rate design. Under this rate design, all fixed costs of providing service including depreciation and return on investment are recovered through the demand charge. About 95% of Questar Pipeline costs are fixed and recovered through these demand charges. Questar Pipeline’s earnings are driven primarily by demand revenues from firm shippers. Since only about 5% of operating costs are recovered through volumetric charges, changes in transportation volumes do not have a significant impact on earnings.

NGL sales were 183% higher in 2010 over 2009 due to a 153% increase in NGL prices and a 13% increase in sales volume. Volumes increased from a processing plant that was completed in 2009 near Price, Utah.

Expenses

Operating and maintenance expenses decreased by 4% to $7.8 million in the first quarter of 2010 compared to $8.1 million in the first quarter of 2009. The decrease was due to lower maintenance costs. General and administrative expenses increased by 23% to $10.6 million in the first quarter of 2010 due to higher overhead costs. Operating, maintenance, general and administrative expenses per dth transported increased to $0.09 in the first quarter of 2010 compared with $0.08 in the first quarter of 2009 because transportation volumes were flat and costs increased 10%. Operating, maintenance, general and administrative expenses include processing and storage costs.

Depreciation expense was up 9% in the first quarter of 2010 compared to the first quarter of 2009 because of plant placed in service.

RETAIL GAS DISTRIBUTION – Questar Gas

Questar Gas, which provides retail natural gas distribution services in Utah, Wyoming and Idaho, reported net income of $33.1 million in the first quarter of 2010 compared with $31.8 million in the first quarter of 2009, a 4% increase. Operating income increased $1.4 million, or 2%, in the 2010-to-2009 first-quarter comparison due to higher margin that more than offset higher costs. Following is a summary of Questar Gas financial and operating results:

	3 Months Ended March 31,
	2010	2009	Change
	(in millions)
Operating Income
Revenues
Residential and commercial sales	$342.0	$392.0	($50.0)
Industrial sales	6.6	2.3	4.3
Transportation for industrial customers	2.9	2.5	0.4
Service	1.7	1.7
Other	7.8	7.2	0.6
Total revenues	361.0	405.7	(44.7)
Cost of natural gas sold	237.0	293.1	(56.1)
Margin	124.0	112.6	11.4
Other operating expenses
Operating and maintenance	39.0	31.0	8.0
General and administrative	11.3	9.8	1.5
Depreciation and amortization	11.1	10.8	0.3
Other taxes	4.0	3.8	0.2
Total other operating expenses	65.4	55.4	10.0
Operating income	$58.6	$  57.2	$1.4

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Operating Statistics
Natural gas volumes (MMdth)
Residential and commercial sales	44.6	44.5	0.1
Industrial sales	1.1	0.3	0.8
Transportation for industrial customers	16.5	16.5
Total industrial	17.6	16.8	0.8
Total deliveries	62.2	61.3	0.9
Natural gas revenue (per dth)
Residential and commercial sales	$7.66	$8.81	($1.15)
Industrial sales	6.01	7.57	(1.56)
Transportation for industrial customers	0.18	0.15	0.03
(Warmer) than normal temperatures		(1%)	1%
Temperature-adjusted usage per customer (dth)	46.6	47.4	(0.8)
Customers at March 31, (thousands)	904.0	892.8	11.2

Margin Analysis

Questar Gas margin (revenues minus gas costs) increased $11.4 million in the first quarter of 2010 compared to the first quarter of 2009. Following is a summary of major changes in Questar Gas margin:

	Change
	2010 vs. 2009
	(in millions)
Customer growth	$1.2
Demand-side management cost recovery	11.5
Recovery of gas-cost portion of bad-debt costs	(1.5)
Other	0.2
Increase	$11.4

At March 31, 2010, Questar Gas served 904,040 customers, up from 892,829 at March 31, 2009. Customer growth increased the margin by $1.2 million in the first quarter of 2010.

Temperature-adjusted usage per customer decreased 2% in the first quarter of 2010 compared to the first quarter of 2009. The impact on the company margin from changes in usage per customer has been mitigated by a conservation-enabling tariff that was approved by the PSCU beginning in 2006.

Weather, as measured in degree days, was normal in the first quarter of 2010 compared to 1% warmer than normal in the first quarter of 2009. A weather-normalization adjustment on customer bills generally offsets financial impacts of moderate temperature variations.

The Company filed a general rate case in December 2009, requesting an allowed return on equity of 10.6%, a mechanism to adjust rates for feeder-line replacement and a continuation of the CET. In April 2010, the Company entered into a stipulation agreement with other parties in the case to settle all issues in the case. The stipulation agreement sets an allowed return on equity of 10.35%, increases customer rates by $5.0 million, establishes a mechanism to adjust rates for feeder-line replacement and continues the CET. The stipulation agreement was approved by the PSCU with the changes in rates effective August 1, 2010.

Expenses

Cost of natural gas sold was down 19% in the first quarter of 2010 compared to the first quarter of 2009 due to lower gas purchase expenses per dth. Questar Gas accounts for purchased-gas costs in accordance with procedures authorized by the PSCU and the PSCW. Purchased-gas costs that are different from those provided for in present rates are accumulated and recovered or credited through future rate changes. As of March 31, 2010, Questar Gas had a $3.1 million under-collected balance in the purchased-gas adjustment account representing costs incurred in excess of costs recovered from customers.

Operating and maintenance expenses increased $8.0 million, or 26%, in the first quarter of 2010 compared to the first quarter of 2009 due primarily to higher demand-side management costs of $11.5 million partially offset by a reduction in bad-debt costs of

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$1.9 million. The demand-side management costs are for the company’s energy efficiency program and are recovered from customers through periodic rate changes. General and administrative expenses increased $1.5 million, or 15% in the 2010 first quarter due to higher overhead costs. Operating, maintenance, general and administrative expenses per customer were $56 in the first quarter of 2010 compared to $46 in the first quarter of 2009 as a result of higher demand-side management costs of $13 per customer.

Depreciation expense increased 3% in the first quarter of 2010 compared to the first quarter of 2009 primarily as a result of plant additions from customer growth and replacement of feeder lines.

Consolidated Results below Operating Income

Interest expense

Interest expense rose 7% in the first quarter of 2010 compared to a year ago due primarily to Market Resources borrowing $300.0 million at a 6.8% interest rate in August 2009 and using the proceeds to repay lower cost variable-rate bank debt.

Realized and unrealized gain (loss) on basis-only swaps

The Company has used basis-only swaps to manage the risk of widening basis differentials. Basis-only swaps do not qualify for hedge accounting. As of December 31, 2009, all of the Company's basis-only swaps were paired with fixed-price swaps and re-designated as cash flow hedges. Changes in the fair value of the derivative instruments subsequent to the re-designation were recorded in AOCI. Fair value changes occurring prior to re-designation were recorded in income. Unrealized gains on basis-only swaps amounted to $34.7 million in the first quarter of 2010 compared to losses of $134.9 million in 2009. Realized losses on settlements of basis-only swaps amounted to $34.7 million in the first quarter of 2010 and $3.4 million in the first quarter of 2009.

Income taxes

The effective combined federal and state income tax rate was 36.8% in the first quarter of 2010 compared with 36.4% in the 2009 period.

LIQUIDITY AND CAPITAL RESOURCES

Operating Activities

Net cash provided from operating activities decreased 24% in the first quarter of 2010 compared to the 2009 quarter due to lower cash flow associated with changes in operating assets and liabilities and lower noncash adjustments to net income. Cash sources from operating assets and liabilities were lower in 2010 primarily due to lower accounts receivable and under-collection in the purchase-gas adjustment account. The year-to-year change in unrealized gains and losses on basis-only swaps represented the single largest noncash adjustment to net income. Net cash provided from operating activities is presented below:

	3 Months Ended March 31,
	2010	2009	Change
	(in millions)
Net income	$150.9	$  67.7	$83.2
Noncash adjustments to net income attributable to Questar	213.0	311.2	(98.2)
Changes in operating assets and liabilities	1.6	101.9	(100.3)
Net cash provided by operating activities	$365.5	$480.8	($115.3)

Investing Activities

A comparison of capital expenditures for the first quarter of 2010 and 2009 plus a forecast for calendar year 2010 are presented below:

			Forecast
	3 Months Ended March 31,		12 Months Ended December 31,
	2010	2009	2010
	(in millions)
Questar E&P	$220.0	$283.6	$   895.1
Wexpro	17.5	26.5	100.0
Gas Management	68.5	39.7	289.0
Questar Pipeline	17.3	25.5	161.4
Questar Gas	26.1	15.0	128.9

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Other		0.2	1.4
Total cash capital expenditures	349.4	390.5	1,575.8
Change in accruals	(24.3)	(127.2)
Total accrued capital expenditures	$325.1	$263.3	$1,575.8

Financing Activities

In the first quarter of 2010, net cash provided by operating activities of $365.5 million exceeded net cash used in investing activities of $349.5 million by $16.0 million. Long-term debt was unchanged in 2010 and short-term debt decreased by a net change of $34.5 million in the first quarter of 2010.

Questar issues commercial paper, rated A-2 by Standard & Poor's and P-2 by Moody's, to meet short-term financing requirements. The Company maintains committed credit lines with banks to provide liquidity support. Credit commitments under the bank lines totaled $435.0 million at March 31, 2010, with no amounts borrowed. Commercial paper outstanding amounted to $134.5 million at March 31, 2010.

At March 31, 2010, combined short-term and long-term debt was 38% and equity was 62% of total capital. Market Resources had $600.0 million of unused capacity under its long-term revolving-credit facility.

ITEM 3.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Questar's primary market-risk exposure arises from changes in the market price for natural gas, oil and NGL, and volatility in interest rates. Energy Trading has long-term contracts for pipeline capacity and is obligated to pay for transportation services with no guarantee that it will be able to fully utilize the contractual capacity of these transportation commitments.

Commodity-Price Risk Management

Market Resources' subsidiaries use commodity-price derivative instruments in the normal course of business to reduce the risk of adverse commodity-price movements. However, these same arrangements typically limit future gains from favorable price movements. Derivative contracts are currently in place for a significant share of Questar E&P-owned gas and oil production and a portion of Energy Trading gas-marketing transactions.

As of March 31, 2010, Market Resources held commodity-price hedging contracts covering about 367.4 million MMBtu of natural gas and 2.3 million barrels of oil. A year earlier, the Market Resources hedging contracts covered 252.4 million MMBtu of natural gas, 0.6 million barrels of oil and natural gas basis-only swaps on an additional 184.9 Bcf. Changes in the fair value of derivative contracts from December 31, 2009 to March 31, 2010 are presented below:

	Cash flow	Basis-only
	Hedges	Swaps	Total
	(in millions)
Net fair value of gas- and oil-derivative contracts   outstanding at Dec. 31, 2009	$138.5	($239.4)	($100.9)
Contracts settled	(45.4)	34.7	(10.7)
Change in gas and oil prices on futures markets	344.9		344.9
Contracts added	(0.8)		(0.8)
Net fair value of gas- and oil-derivative contracts   outstanding at March 31, 2010	$437.2	($204.7)	$232.5

A table of the net fair value of gas- and oil-derivative contracts as of March 31, 2010, is shown below. Most of the fixed-priced swaps will settle in the next 12 months and the fair value of cash-flow hedges will be reclassified from Accumulated Other Comprehensive Income to the Consolidated Statements of Income:

	Cash flow	Basis-only
	Hedges	Swaps	Total
	(in millions)
Contracts maturing by March 31, 2011	$292.0	($118.2)	$173.8
Contracts maturing between April 1, 2011 and March 31, 2012	96.4	(86.5)	9.9

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Contracts maturing between April 1, 2012 and March 31, 2013	25.8		25.8
Contracts maturing between April 1, 2013 and March 31, 2014	23.0		23.0
Net fair value of gas- and oil-derivative contracts   outstanding at March 31, 2010	$437.2	($204.7)	$232.5

The following table shows sensitivity of fair value of gas- and oil-derivative contracts and basis-only swaps to changes in the market price of gas and oil and basis differentials:

	March 31,	December 31,
	2010	2009
	(in millions)
Net fair value - asset (liability)	$232.5	($100.9)
Fair value if market prices of gas and oil and basis differentials decline by 10%	427.6	174.2
Fair value if market prices of gas and oil and basis differentials increase by 10%	37.4	(375.8)

Interest-Rate Risk Management

As of March 31, 2010, Questar had $1,979.9 million principal amount of fixed-rate long-term debt and $200.0 million of variable-rate long-term debt.

Forward-Looking Statements

This quarterly report may contain or incorporate by reference information that includes or is based upon "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements give expectations or forecasts of future events. You can identify these statements by the fact that they do not relate strictly to historical or current facts. They use words such as "anticipate," "estimate," "expect," "project," "intend," "plan," "believe," and other words and terms of similar meaning in connection with a discussion of future operating or financial performance. In particular, these include statements relating to future actions, prospective services or products, future performance or results of current and anticipated services or products, exploration efforts, expenses, the outcome of contingencies such as legal proceedings, trends in operations and financial results.

Any or all forward-looking statements may turn out to be wrong. They can be affected by inaccurate assumptions or by known or unknown risks and uncertainties. Many such factors will be important in determining actual future results. These statements are based on current expectations and the current economic environment. They involve a number of risks and uncertainties that are difficult to predict. These statements are not guarantees of future performance. Actual results could differ materially from those expressed or implied in the forward-looking statements. Among factors that could cause actual results to differ materially are:

-

the risk factors discussed in Part I, Item 1A of the Company's Annual Report on Form 10-K for the year ended December 31, 2009;

-

general economic conditions, including the performance of financial markets and interest rates;

-

changes in industry trends;

-

changes in laws or regulations; and

-

other factors, most of which are beyond the Company's control.

Questar undertakes no obligation to publicly correct or update the forward-looking statements in this quarterly report, in other documents, or on the Web site to reflect future events or circumstances. All such statements are expressly qualified by this cautionary statement.

ITEM 4.  CONTROLS AND PROCEDURES.

Evaluation of Disclosure Controls and Procedures.

The Company's Chief Executive Officer and Chief Financial Officer have evaluated the effectiveness of the Company's disclosure controls and procedures (as such term is defined in Rules 13a-15(e) under the Securities Exchange Act of 1934, as amended) as of March 31, 2010. Based on such evaluation, such officers have concluded that, as of March 31, 2010, the Company's disclosure controls and procedures are effective in alerting them on a timely basis to material information relating to the Company, including its consolidated subsidiaries, required to be included in the Company's reports filed or submitted under the Exchange Act. The Company's Chief Executive Officer and Chief Financial Officer also concluded that the controls and procedures were effective in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the Company's management including its principal executive and financial officers or persons performing similar functions as appropriate to allow timely decisions regarding required disclosure.

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Changes in Internal Controls.

There were no changes in the Company's internal controls over financial reporting that occurred during the quarter ended March 31, 2010, that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

PART II.  OTHER INFORMATION

ITEM 1.  LEGAL PROCEEDINGS.

Questar is involved in various commercial and regulatory claims and litigation and other legal proceedings that arise in the ordinary course of its business. Management does not believe any of them will have a material adverse effect on the Company's financial position, results of operations or cash flows. A liability is recorded for a loss contingency when its occurrence is probable and damages can be reasonably estimated based on the anticipated most likely outcome. Disclosures are provided for contingencies reasonably likely to occur which would have a material adverse effect on the Company's financial position, results of operations or cash flows. Some of the claims involve highly complex issues relating to liability, damages and other matters subject to substantial uncertainties and, therefore, the probability of liability or an estimate of loss cannot be reasonably determined.

Environmental Claims

In United States of America v. Questar Gas Management Co., Civil No. 208CV167, filed on February 29, 2008, in Utah Federal District Court, the Environmental Protection Agency (EPA) alleges that Gas Management violated the federal Clean Air Act (CAA) and seeks substantial penalties and a permanent injunction involving the manner of operation of five compressor stations located in the Uinta Basin of eastern Utah. EPA further alleges that the facilities are located within the original boundaries of the former Uncompahgre Indian Reservation and are therefore within "Indian Country." EPA asserts primary CAA jurisdiction over "Indian Country" where state CAA programs do not apply. EPA contends that the potential to emit, on a hypothetically uncontrolled basis, for Gas Management's facilities render them "major sources" of emissions for criteria and hazardous air pollutants. Categorization of the facilities as "major sources" affects the particular regulatory program applicable to those facilities. EPA claims that Gas Management failed to obtain the necessary major source pre-construction or modification permits, and failed to comply with hazardous air-pollutant regulations for testing and reporting, among other things. Gas Management contends that its facilities have pollution controls installed that reduce their actual air emissions below major source thresholds, rendering them subject to different regulatory requirements. Gas Management intends to vigorously defend against the EPA's claims, and believes that the major source permitting and regulatory requirements at issue can be legally avoided by applying Utah's CAA program or EPA's prior practice for similar facilities elsewhere in Indian Country, among other defenses. Because of the complexities and uncertainties of this legal dispute, it is difficult to predict all reasonably possible outcomes; however, management believes the Company has accrued a reasonable loss contingency that is an immaterial amount, for the anticipated most likely outcome.

The Ute Indian Tribe has intervened as a party to the above EPA CAA enforcement action, but has been constrained by the court’s intervention order to claims based on the same questions of law and fact common to the government’s CAA claims. The Tribe alleges claims against Gas Management based on tort and public nuisance and seeks injunctive relief and monetary damages. Gas Management has filed a motion to dismiss the Tribe’s complaint in intervention for lacking commonality with the government’s claims. As a result, the Tribe seeks to cancel its comprehensive January 2005, Surface Use and Access Concession Agreement (SUA) with Questar and its affiliates and threatens to deny future access to Questar affiliates in carrying out development and operations. The parties have tendered cross-claims of breach under the SUA and have triggered an informal resolution process likely leading to arbitration separate from the pending CAA litigation. Questar will vigorously defend its rights under the SUA.

ITEM 2.  UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS.

Questar had no unregistered sales of equity during the first quarter of 2010. Questar repurchased shares in conjunction with tax-payment elections under the Company Long-term Stock Incentive Plan and rollover shares used in exercising stock options. The following table sets forth the Company's purchases of common stock registered under Section 12 of the Exchange Act that occurred during the quarter ended March 31, 2010:

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2010	Number of Shares Purchased*	Average Price per Share	Total Number of Shares Purchased as Part of Publicly Announced Plans	Maximum Number of Shares that May Yet Be Purchased Under the Plans
January	27,013	$44.39	-	-
February	79,620	41.37	-	-
March	38,886	44.01	-	-
Total	145,519	$42.64	-	-

*Excludes any fractional shares purchased from terminating participants in the Questar Dividend Reinvestment and Stock Purchase Plan and any shares of restricted stock forfeited when failing to satisfy vesting conditions.

ITEM 6.  EXHIBITS.

The following exhibits are being filed as part of this report:

Exhibit No.

Exhibits

  31.1.

Certification signed by Keith O. Rattie, Questar Chairman, President and Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

  31.2.

Certification signed by Richard J. Doleshek, Questar Executive Vice President and Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

  32.

Certification signed by Keith O. Rattie and Richard J. Doleshek, Questar Chairman, President and Chief Executive Officer and Executive Vice President and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.SCH

XBRL Taxonomy Extension Schema.

101.CAL

XBRL Taxonomy Extension Calculation Linkbase.

101.LAB

XBRL Taxonomy Extension Label Linkbase.

101.PRE

XBRL Taxonomy Extension Presentation Linkbase.

101.INS

XBRL Instance Document.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

QUESTAR CORPORATION

(Registrant)

May 5, 2010

/s/Keith O. Rattie

Keith O. Rattie, Chairman of the Board,

President and Chief Executive Officer

May 5, 2010

/s/Richard J. Doleshek

Richard J. Doleshek,

Executive Vice President

and Chief Financial Officer

Questar 2010 Form 10-Q

28

Exhibits List

Exhibits

  31.1.

Certification signed by Keith O. Rattie, Questar Chairman, President and Chief Executive Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

  31.2.

Certification signed by Richard J. Doleshek, Questar Executive Vice President and Chief Financial Officer, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

  32.

Certification signed by Keith O. Rattie and Richard J. Doleshek, Questar Chairman, President and Chief Executive Officer and Executive Vice President and Chief Financial Officer, respectively, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.SCH

XBRL Taxonomy Extension Schema.

101.CAL

XBRL Taxonomy Extension Calculation Linkbase.

101.LAB

XBRL Taxonomy Extension Label Linkbase.

101.PRE

XBRL Taxonomy Extension Presentation Linkbase.

101.INS

XBRL Instance Document.

Questar 2010 Form 10-Q

29